The present invention relates to the absorption of CO.sub.2 from light hydrocarbons at partial pressures in excess of 120 psia and where the CO.sub.2 content of the gas exceeds 45 mol percent. The invention is particularly applicable to carbon dioxide flooding projects for enhanced oil recovery or the processing of hydrocarbon gas streams naturally containing the high percentages of CO.sub.2.
In CO.sub.2 flooding projects for enhanced oil recovery, CO.sub.2 is injected into the formation at a typical pressure range of 1,000-3,000 psia. The affect of the pressure along with the miscibility of CO.sub.2 in the oil in the reservoir result in the additional production of oil. Usually about 6,000-18,000 SCF of CO.sub.2 are required for recovery of one barrel of oil.
For an initial period of time, there is little or no CO.sub.2 exiting the wellhead with the oil. However, after this CO.sub.2 breakthrough period which may commonly occur six months to thirty months after the initiation of the flood, about 50-80% of the injected CO.sub.2 breaks through the reservoir and exits the wellhead at low pressure, along with hydrocarbon products. The balance of the CO.sub.2 dissipates in the formation and is not recoverable. Recovery of the wellhead CO.sub.2 and the associated light hydrocarbons is an essential factor to make the enhanced oil recovery by CO.sub.2 flood an economical operation. A typical gas composition after this CO.sub.2 breakthrough may be commonly in the following range:
______________________________________ Component Mol % ______________________________________ CO.sub.2 60-90 H.sub.2 S 0-3 CH.sub.4 5-15 C.sub.2 H.sub.6 3-10 C.sub.3 -H.sub.8 2-6 C.sub.4.sup.+ 2-5 N.sub.2 0-2 ______________________________________
After the breakthrough, the CO.sub.2 content may increase gradually with time and the hydrocarbon content may decrease at a moderate rate as the reservoir is depleted. When the reservoir is abandoned (say, after approximately ten years), the CO.sub.2 content in the wellhead gas may exceed 90%.
The separation of the CO.sub.2 is required since the CO.sub.2 is a valuable fluid for reinjection into the reservoir, thus reducing the CO.sub.2 makeup rate. Also, the separation produces valuable sales gas and liquid hydrocarbons products.
The specifications for the reinjected CO.sub.2 are a function of the reservoir characteristics, but a common specification range may be as follows:
______________________________________ 1. CO.sub.2 injection pressure: 1,000-3,000 psia 2. CO.sub.2 purity: &gt;95% 3. H.sub.2 S content: &lt;100 ppm ______________________________________
Usually higher CO.sub.2 purity results in higher yield of liquid and gas products. For example, typical specifications for a sales gas are:
______________________________________ 1. Methane content: &gt;90% 2. CO.sub.2 content: &lt;5% 3. Sulfur (H.sub.2 S, CS.sub.2, COS): &lt;4 ppm 4. Pressure: 500-1,200 psia 5. Higher heat valve: &gt;950/Btu/scf ______________________________________
There are several major prior art approaches for the separation recoveries of CO.sub.2 and hydrocarbons. One is the amine or other alkaline scrubbing of CO.sub.2 at 100-400 psia (total pressure) and a combination of pressure and temperature swing for the regeneration of the CO.sub.2. This system requires relatively high heat energy for the chemical breakdown to regenerate the CO.sub.2 and energy to recompress the CO.sub.2 to reinjection pressure. Another system is membrane separation at pressures of 300-1,000 psia where the bulk of the CO.sub.2 containing small but still undesirable portions of hydrocarbons are recovered as permeate at pressures of about 30-100 psia and then recompressed for reinjection. There is a large pressure drop and thus high energy for multistage recompression.
A third system is the use of a physical solvent such as Selexol where CO.sub.2 and H.sub.2 S along with some hydrocarbons are absorbed at pressure of 200-800 psia. A portion of the CO.sub.2 can be recovered at pressure of about 50-100 psia while the balance of it is recovered at atmospheric pressure. The CO.sub.2 is then recompressed to the injection pressure which again requires considerable energy. Also, the fact that some of the hydrocarbons and particularly the C.sub.2 + are absorbed in the physical solvent is a drawback. Another system is cryogenic distillation where a liquid CO.sub.2 is separated from hydrocarbons at a pressure range of 250-450 psia where H.sub.2 S is either absorbed upstream selectively to CO.sub.2 by amine solution (such as M.D.E.A.) or cryogenically separated along with the C.sub.3 + products.
One of the potential obstacles which may be encountered in the fractionation of CO.sub.2 and hydrocarbons is CO.sub.2 freezing occuring at about -70.degree. F. This freezing could occur in the CH.sub.4 --CO.sub.2 separation column. The second obstacle is the CO.sub.2 /C.sub.2 H.sub.6 azeotrope formation at about 70 mol % CO.sub.2 and 30 mol % C.sub.2 H.sub.6 for a binary system, which makes it difficult to separate C.sub.2 H.sub.6 from CO.sub.2. These problems have been solved in the past by injection of C.sub.4 + and LPG into the feed gas or the fractionation tower. The C.sub.4 + increases the relative volatility of CO.sub.2 over C.sub.2 H.sub.6. The C.sub.4 + also suppresses CO.sub.2 freezing, thus allowing CO.sub.2 --CH.sub.4 fractionation at low temperatures.
The concept of using CO.sub.2 absorption with water has been used in the past for scrubbing CO.sub.2 from ammonia synthesis gas; however, the CO.sub.2 in that application was a low pressure (under 30 psia) waste product which was merely vented to the atmosphere, its concentration was under 35 mol % and the bulk of the gas was CO, H.sub.2 and N.sub.2 rather than CH.sub.4 and C.sub.2 H.sub.6 as in the present invention. The co-absorption of CO.sub.2 and H.sub.2 S by water in natural gas treating has also been done in the past. However, the co-absorbed CO.sub.2 was flashed along with the H.sub.2 S at low pressure (under 30 psia) only as a sulfur plant feed gas. There was no separation of CO.sub.2 from H.sub.2 S or any other attempt to recover CO.sub.2.
Another approach which has been proposed for CO.sub.2 --C.sub.2 H.sub.6 separation is carried out by a membrane which is preceded by a cryogenic demethanizer using the C.sub.4 + recycle mentioned above. The CO.sub.2 permeate has to be recompressed by a multistage compressor to the well injection pressure.
An approach which uses liquid CO.sub.2 extraction by liquid water (total liquid phase), where CO.sub.2 is separated from ethane has been proposed in copending Patent Application Ser. No. 583,467, filed Feb. 24, 1984.